Testing additives for production enhancement treatments

ABSTRACT

Fluid tests may be performed to determine suitability of an additive for a production enhancement treatment. In one aspect, a measuring device is used to determine a result of adding a sample of solid material to a test fluid that includes an additive. The result may include, for example, a change in surface tension, a change in contact angle, and/or another result. The measured result is used to determine the suitability of the additive for use in a stimulation treatment for a subterranean formation. For example, the additive may be determined suitable for use during a pad phase of a fracture treatment, during a proppant-laden phase of a fracture treatment, and/or for other phases and/or types of stimulation treatments.

CROSS REFERENCE TO RELATED APPLICATION

This application is a continuation and claims the benefit under 35U.S.C. §120 of U.S. patent application Ser. No. 12,650,934, entitled“Testing Additives for Production Enhancement Treatments,” filed Dec.31, 2009, which is incorporated herein by reference in its entirety.

BACKGROUND

Oil and gas wells produce oil, gas and/or byproducts from undergroundreservoirs. Oil and gas reservoirs are formations of rock containing oiland/or gas. The type and properties of the rock may vary by reservoirand also within reservoirs. For example, the porosity and permeabilityof a reservoir rock may vary from reservoir to reservoir and from wellto well in a reservoir. The porosity is the percentage of core volume,or void space, within the reservoir rock that can contain fluids. Thepermeability is a measure of the reservoir rock's ability to flow ortransmit fluids.

Capillary pressure refers to a difference in pressure across a fluidinterface in a capillary. Capillary pressures in a reservoir generallydepend on the porosity and permeability of the rock as well as otherproperties of the rock and the fluids. Unconventional reservoirs, whichmay include shale reservoirs, tight gas reservoirs, and other types oflow permeability reservoirs, typically exhibit high capillary pressures.High capillary pressures in a reservoir may lead to phase trappingrendering that phase immobile in the reservoir, which may inhibit orhinder production of resources.

Oil and gas production from a well may be stimulated by fracture, acidor other production enhancement treatments. In a fracture treatment,fluids are pumped downhole under high pressure to hydraulically fracturethe reservoir rock in order to connect a larger portion of the reservoirto the wellbore. In some implementations, fracture fluids withoutproppants are injected into the formation to fracture the formation, andfracturing fluid with proppants are then pumped into the formation tohold the fractures open.

SUMMARY

In a general aspect, fluid testing techniques are used to identifyfluids that are suitable for a production enhancement treatment.

In one aspect, a measuring device is used to determine a result ofadding a sample of solid material to a test fluid that includes anadditive. The suitability of the additive for use in a stimulationtreatment for a subterranean formation is determined based at least inpart on the result.

Some embodiments may include one or more of the following features.Determining the result includes using the measuring device to measure afirst surface tension of the test fluid before adding the sample to thetest fluid. Determining the result includes using the measuring deviceto measure a second surface tension of the test fluid after adding thesample to the test fluid. The result is the difference between the firstsurface tension and the second surface tension. The second surfacetension is substantially equal to the first surface tension, anddetermining the suitability includes determining that the additive issuitable for a pad phase of the stimulation treatment. Determining theresult includes using the measuring device to measure a first contactangle between the test fluid and a test surface before adding the sampleto the test fluid. Determining the result includes using the measuringdevice to measure a second contact angle between the test fluid and thetest surface after adding the sample to the test fluid. The response isa difference between the first contact angle and the second contactangle. The second contact angle is greater than the first contact angle,and determining the suitability includes determining that the additiveis suitable for a proppant phase of the stimulation treatment. The testfluid is a first test fluid that includes a first concentration of theadditive in a solvent, the sample is a first sample, and the result is afirst result. The measuring device is used to determine a second resultof adding a second sample of the solid material to a second test fluidthat includes a second concentration of the additive and the solvent.The measuring device is used to determine a third result of adding athird sample of the solid material to a third test fluid that includes athird concentration of the additive and the solvent. The suitability isdetermined based on the first response, the second response, and thethird response. The third concentration is the critical micelleconcentration. The sample includes at least one of granular rockmaterial, granular mineral material, graded sand, a proppant material,cuttings from the subterranean formation, or crushed material from thesubterranean formation. Determining a suitability of the additiveincludes using a data processor to analyze the response. Determining asuitability of the additive includes determining that the additive is anon-adsorbing surfactant, a weakly-adsorbing surfactant, or astrongly-adsorbing surfactant.

In one aspect, information on an additive selected for treating asubterranean formation is received. The additive is selected fortreating the subterranean formation based at least in part on a measuredresult of adding a sample of a solid material to a test fluid comprisingthe additive. The additive is injected into the subterranean formationthrough a well bore defined in the subterranean formation.

Some embodiments may include one or more of the following features. Thesample of solid material includes crushed material and/or cuttings fromthe subterranean formation. The subterranean formation is a firstsubterranean formation, and the sample includes crushed material and/orcuttings from a second subterranean formation. The sample includes aproppant material, and injecting the additive includes injecting theadditive and the proppant material into the subterranean formation. Thesample includes a proppant material, and injecting the additive includesinjecting the additive into a region of the subterranean formation wherethe proppant material resides. The additive is an additive selectedbased on the measured result of adding the sample to the test fluidincluding no change in a surface tension of the test fluid and/or themeasured result of adding the sample to the test fluid including anincrease in a contact angle of the test fluid and a test surface.

In one aspect, a system includes a fluid testing subsystem and astimulation treatment subsystem. The fluid testing subsystem determinesa suitability of an additive for a stimulation treatment. Thesuitability is determined based at least in part on a result of adding asample of a solid material to a test fluid that includes the additive.The stimulation treatment subsystem applies the additive to asubterranean formation through a well bore defined in the subterraneanformation.

Some embodiments may include one or more of the following features. Thesubterranean formation includes shale, and the well bore includes ahorizontal well bore. The subterranean formation includes a formationmatrix and a fracture network. The fluid testing subsystem includes afluid container that receives a test fluid comprising the additive andthe sample of solid material. The fluid testing subsystem includes atensiometer that measures a surface tension of the test fluid. The fluidtesting subsystem includes a contact angle goniometer that measures acontact angle between the test fluid and a test surface. The stimulationtreatment subsystem includes a tubular conduit installed in the wellbore, a pump that communicates a treatment fluid comprising the additiveinto the tubular conduit, and an outlet in the well bore that receivesthe treatment fluid from the tubular conduit and communicates thetreatment fluid into the subterranean formation.

The details of one or more embodiments of the invention are set forth inthe accompanying drawings and the description below. Other features,objects, and advantages of the invention will be apparent from thedescription and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of an example well system.

FIG. 2 is a diagram of an example fluid testing system.

FIG. 3 is a plot of example data from a fluid test.

FIG. 4 is a plot of example data from a fluid test.

FIG. 5 is a flow chart of an example technique for applying a hydraulictreatment to a subterranean formation.

FIG. 6 is a flow chart of an example fluid testing technique.

FIG. 7 is a flow chart of another example fluid testing technique.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

FIG. 1 shows an example well system 100. The example well system 100includes a well bore 101 in a subterranean region 103 beneath a surface106. The well bore 101 may be used to apply a production enhancementtreatment to and/or produce resources from the subterranean region 103;the well system 100 can include one or more additional wells used fortreatment, production, observation, and/or other activities. The examplewell bore 101 intersects a subterranean formation 114, which may includea low permeability formation. Examples of low permeability formationsinclude shale formations, coal formations, tight gas formations, and/orother types of formations. In some cases, low permeability rock mayexhibit permeability less than one milliDarcy (mD). For example,permeability in shale formations may, in some instances, range fromapproximately 10⁻⁶ mD to approximately 10⁻³ mD; and permeability in atight gas formation may, in some instances, range from approximately10⁻³ mD to approximately 10⁻¹ mD.

Permeability refers generally to the reservoir rock's ability to flow ortransmit fluids. Absolute permeability refers to the rock's ability toflow or transmit a fluid when a single fluid is present in the rock.Effective permeability refers to the rock's ability to flow or transmita particular fluid when other fluids are present in the rock. Forexample, a rock's effective permeability to hydrocarbons may refer tothe rock's ability to flow or transmit hydrocarbons in the presence ofwater and/or other fluids. Low permeability formations typically exhibithigh capillary pressures. Capillary pressure refers to a difference inpressure across a fluid interface in a capillary. High capillarypressures in a formation can cause phase trapping (e.g., waterblockages, and/or other immobilized phases) in the formation. A phasetrapping may be created by a fluid or a gas immobilized in the formationmatrix. The immobilized phase may include water, hydrocarbon, gas,and/or others. Water blockages and other types of phase trapping mayinhibit or hinder the migration of fluids through the formation matrixand thus have a negative impact on production.

The well system 100 of FIG. 1 may include, communicate with, and/orreceive data from one or more fluid testing subsystems 120. A fluidtesting subsystem 120 may test fluids for use in production enhancementtreatments. For example, the fluid testing subsystem 120 may identifyadditives that promote fracturing fluid flowback and/or additives thatremediate a trapped phase. In some implementations, the fluid testingsubsystem 120 can be used to identify strongly adsorbing surfactants,weakly-adsorbing surfactants, non-adsorbing surfactants, and other typesof additives. The fluid testing subsystem 120 can be a remote systemthat performs fluid tests at a location remote from a well site prior totreatment. The fluid testing subsystem 120 can be an on-site system thatperforms fluid tests near the well site. The fluid testing subsystem 120can include both an on-site fluid testing subsystem and a remote fluidtesting subsystem that operate independently or collaboratively. In someimplementations, one or more constituents of a treatment fluid 117 isselected based on fluid tests performed by the fluid testing subsystem120, and the treatment fluid 117 is injected into the formation 114 toenhance production.

In some implementations, the treatment fluid 117 enhances production byincreasing all or part of the formation's effective permeability tohydrocarbons. For example, a surfactant may be included in the treatmentfluid 117 based on the surfactant's tendency to adsorb to solid surfacesin the formation 114 (e.g., surfaces of proppant material in theformation 114) and thereby increase the rate at which hydrocarbons flowthrough the formation 114. In some examples, a strongly-adsorbingsurfactant can modify the wettability of a solid surface, leading toless oil-wet (i.e., more water-wet) surfaces, which can improvetransmission of hydrocarbons along the solid surface. An additive thatstrongly adsorbs to a solid surface may be identified by one or morefluid testing techniques. For example, a fluid testing subsystem 120 mayperform one or more fluid tests to identify strongly-adsorbingsurfactants for a stimulation treatment.

In some implementations, the treatment fluid 117 enhances production byreducing or maintaining capillary pressure in all or part of theformation 114. For example, a surfactant may be included in thetreatment fluid 117 based on the surfactant's tendency not to adsorb tosolid surfaces in the formation 114 (e.g., capillary surfaces in theformation 114). In some examples, a treatment fluid 117 that includes aweakly-adsorbing or non-adsorbing surfactant can be more efficientlyrecovered from the formation 114, and therefore the weakly-adsorbing ornon-adsorbing surfactant prevents or reduces a tendency of the treatmentfluid 117 to cause water blockages in the formation 114. An additivethat weakly adsorbs (or does not adsorb) to a solid surface may beidentified by one or more fluid testing techniques. For example, thefluid testing subsystem 120 may perform one or more fluid tests toidentify weakly-adsorbing and/or non-adsorbing surfactants for astimulation treatment.

The example fluid testing subsystem 120 can measure properties of testfluids and determine how the measured properties change when the testfluids are exposed to a mineral surface. For example, the fluid testingsubsystem 120 can measure the response of a test fluid to addingproppant or rock formation material to the test fluid. In someimplementations, the measured response may indicate a change or nochange in surface tension of the test fluid, a change or no change incontact angle of the test fluid, and/or a different response. Multipletest fluids, each having a different concentration of an additive in asolvent, can be measured, and the measurements can be used to selectfluids and/or additives for stimulation treatment to be applied to asubterranean formation. The fluid testing subsystem 120 may include theexample fluid testing system 200 of FIG. 2 or a different fluid testingsubsystem. The fluid testing subsystem 120 may be adapted to perform theexample fluid testing techniques shown in FIGS. 3, 4, 5, 6, and 7 and/orother fluid testing techniques.

A stimulation treatment can be designed based on data generated by thefluid testing subsystem 120, and the stimulation treatment can beapplied to the formation 114 through the well bore 101. For example, thestimulation treatment may include a fracture treatment applied to thesubterranean formation 114 by a fracture treatment subsystem 124. Theexample fracture treatment subsystem 124 shown in FIG. 1 includesinstrument trucks 116, pump trucks 119, and other equipment. Thestimulation treatment may be applied through any suitable type of wellbore and/or multiple well bores. The example well bore 101 shown in FIG.1 includes a vertical well bore. A well bore may additionally oralternatively include one or more slant well bores, one or morehorizontal well bores, one or more deviated well bores, and/or othertypes of well bores. A casing 108 may be cemented or otherwise securedin the well bore 101. Perforations 112 may be formed in the casing 108to allow treatment fluids, proppants, and/or other materials to flowinto the subterranean formation 114, and/or to allow oil, gas,by-products, and other materials to flow into the well bore 101 and beproduced to the surface 106. Perforations 112 may be formed using shapecharges, a perforating gun, and/or other tools. A stimulation treatmentmay be applied through an un-cased well bore and/or through an un-casedportion of a well bore.

The working string 107 disposed in the well bore 101 may include coiledtubing, sectioned pipe, and/or other types of conduit. A fracturing tool110 may be coupled to the working string 107. In some cases, a fracturetreatment and/or another type of stimulation treatment can be appliedwithout use of a fracturing tool. The fracturing tool 110 can include ahydrajetting/fracturing tool and/or another type of fracturing tool.Example hydrajetting/fracturing tools include the SURGIFRAC tool(manufactured by HALLIBURTON), the COBRA FRAC tool (manufactured byHALLIBURTON), and/or others. The packers 104 shown in FIG. 1 seal theannulus of the well bore 101 above and below the subterranean formation114. Packers 104 may include mechanical packers, fluid inflatablepackers, sand packers, and/or other types of packers. Packers 104 may beplaced in additional and/or different locations in the well bore 101.

The pump trucks 119 are coupled to the working string 107 at the surface106. The pump trucks 119 may include mobile vehicles, immobileinstallations, skids, hoses, tubes, fluid tanks or reservoirs, pumps,valves, and/or other suitable structures and equipment. Duringoperation, the pump trucks 119 pump treatment fluid 117 down the wellbore 101, and the treatment fluid 117 is injected into the subterraneanformation 114. The treatment fluid 117 may include a pad, proppants, aflush fluid, and/or other materials. For example, a fracture treatmentmay include a pad phase, where a pad (which typically includes fracturefluids without proppants) is pumped down the well bore and injected intothe surrounding the formation to induce fracture. After the pad phase,the fracture treatment may include a subsequent proppant phase, wherefracturing fluids containing proppants are pumped into the formation.The injected proppants may hold the fractures open to stimulateproduction from the formation. After the proppant phase, a fluid flushmay be pumped into the well bore to clean the well bore of proppantsand/or other materials. Additives may be included in the treatment fluid117. The additives may lower the surface tension of the treatment fluid117 and/or alter the contact angle of the treatment fluid 117 on mineralsurfaces exposed to the fracturing fluid. The reduction in surfacetension and/or alteration of the contact angle of the non-wetting phaseon the treated mineral surfaces is desirable as both factors can reducecapillary pressures and thus minimize phase immobilization in thereservoir matrix.

The treatment fluid 117 may include a mixture of fluids, which mayinclude one or more additives, and in some instances, a proppantmaterial. The proppant, the fluids, the concentration of the fluidconstituents, and/or other properties of the treatment fluid 117 may beselected based on a fluid test performed by the fluid testing subsystem120. For example, the treatment fluid 117 may include astrongly-adsorbing surfactant, a weakly-adsorbing surfactant, anon-adsorbing surfactant, and/or another type of surfactant selected toenhance productivity from the subterranean formation 114. Differenttreatment fluids may be selected for each phase of production based onthe fluid test results.

The instrument trucks 116 provided at the surface 106 may include mobilevehicles, immobile installations, and/or other suitable structures. Theinstrument trucks 116 may include a technical command center. Theexample instrument trucks 116 include a fracture control system thatmonitors and controls the fracture treatment. The fracture controlsubsystem may include a local computing system, and/or the fracturecontrol subsystem may communicate with a remote computing subsystem. Thefracture control system may control the pump trucks 119, fracturing tool110, fluid valves, and/or other equipment used to apply the fracturetreatment. The well system 100 may also include surface and down-holesensors to measure pressure, rate, temperature and/or other parametersof treatment and/or production. The well system 100 may include pumpcontrols and/or other types of controls for starting, stopping and/orotherwise controlling pumping as well as controls for selecting and/orotherwise controlling fluids pumped during the fracture treatment. Thefracture control system in the instrument trucks 116 can communicatewith the surface and/or subsurface sensor, instruments, and otherequipment to monitor and control the fracture treatment.

The example instrument trucks 116 shown in FIG. 1 communicate with thepump trucks 119, the surface and subsurface instruments, the fluidtesting subsystem 120, and/or other systems and subsystems through oneor more communication links 118. The communication links 118 can includemultiple uncoupled communication links and/or one or more networks ofcoupled communication links. The communication links 118 may includewired and/or wireless communications systems. For example, surfacesensors and pump controls may communicate with the fracture controlsystem through a wired or wireless link, down-hole sensors maycommunicate to a receiver at the surface 106 through a wired or wirelesslink, and the receiver may be coupled by a wired or wireless link to thefracture control system. As another example, the instrument trucks 116may communicate with the pump trucks 119 and/or the remote fluid testingsubsystem 120 via wired and/or wireless digital data communicationnetworks, wired and/or wireless analog communication links, and/or othertypes of communication links.

The example subterranean formation 114 in FIG. 1 includes a fracturenetwork 113. The fracture network 113 may include natural fractures,complex fractures, fractures 115 resulting from a fracture treatmentapplied to the subterranean formation 114, and/or other types offractures. The fractures 115 resulting from a fracture treatment mayinclude fractures resulting from a mini fracture test treatment, aregular or full fracture treatment, a follow-on fracture treatment, are-fracture treatment, a final fracture treatment and/or another type offracture treatment. The fracture network 113 may contain proppantsinjected into the subterranean formation 114 during the fracturetreatment. The fracture network 113, which may include the proppedfracture network, natural fractures, propagated fractures, etc.,typically has a much higher permeability than the formation matrix. Forexample, the permeability of the fracture network 113 may range, in somecases from approximately 10⁻¹ mD to approximately 10² mD. In someexamples, the permeability of the fracture network 113 is approximatelyeight to twelve orders of magnitude larger than the permeability of theformation matrix.

Thus, two regimes may be considered when choosing asurfactant/micro-emulsion package for hydraulic fracture stimulation inlow permeability formations: the propped fracture regime and theformation matrix regime. In some low permeability formations, a stronglyadsorbing surfactant in the fracture network enhances production byincreasing the effective permeability of the fracture network tohydrocarbons, and a weakly adsorbing surfactant in the formation matrixenhances production by reducing water blockages in the formation matrix.As such, in some instances, different surfactant properties aredesirable for the formation matrix regime and the propped fractureregime, and different surfactants can be used in different phases of astimulation treatment to improve well performance. For example, in someinstances, well performance may be maximized by choosing (1) aweakly-adsorbing or non-adsorbing surfactant for use in the pad phase ofa treatment and (2) a strongly adsorbing surfactant for use inproppant-laden phase of the treatment. In the pad phase, theweakly-adsorbing or non-adsorbing surfactant may help maintain lowsurface tensions of both the injected and recovered fluids, which canreduce or minimize water blocks in the formation matrix. In theproppant-laden phase, the surfactant and/or the surfactant concentrationcan be chosen to ensure monolayer surfactant coverage on the proppant.Other stimulation treatment packages may use multiple different types ofsurfactants in one or more phase of treatment to improve production fromboth the formation matrix and the fracture network.

In one aspect of operation, the fracturing tool 110 is coupled to theworking string 107 and positioned in the treatment well 101. The packers104 are set to isolate the subterranean formation 114. The pump trucks114 pump fracture fluid 117 down the working string 107 to thefracturing tool 110. The fracture fluid 117 exits the fracturing tool110 and fractures the subterranean formation 114. In someimplementations, the fracture fluid may include a fluid pad pumped downthe well bore 101 to create or expand the fractures 115 in thesubterranean formation 114, and proppants may then be pumped into thefracture network 113, followed by a fluid flush. The proppant may bepumped into the propagated fractures 115, a natural fracture network, acomplex fracture network, and/or other types of fractures. In someimplementations, the fracture treatment is performed in a differentmanner. For example, the fracture treatment may be applied throughmultiple well bores.

FIG. 2 is a diagram of an example fluid testing system 200. The fluidtesting system 200 can be the fluid testing subsystem 120 of FIG. 1. Thefluid testing system 200 may be used to determine suitability of anadditive for one or more phases of a stimulation treatment. For example,the fluid testing system 200 may be used to identify an additive to beapplied to the formation matrix during a pad phase of treatment, anadditive to be applied to the fracture network during a proppant-ladenphase of treatment, and/or other additives. The fluid testing system 200may be used to select a treatment fluid, or a component of a treatmentfluid, based on physical properties of the (low permeability) formationmatrix regime and/or properties of the (higher permeability) fracturenetwork regime.

The difference in permeability between the formation matrix regime andthe fracture network regime is typically accompanied by a concomitantdifference in average pore radius between the regimes. For example,average pore radius may be related to permeability by the equation√{square root over (k)}≈2 r, where k is the permeability in mD and r isthe average pore radius in micrometers (μm). From the propped fractureregime to the low permeability formation matrix regime, the average poremay radius may decrease by four to five orders of magnitude, in somecases.

The difference in permeability between the propped fracture regime andthe formation matrix regime may lead to different capillary pressures inthe two regimes. For example, capillary pressure can be expressed interms of the permeability k as follows:

$\begin{matrix}{P_{c} = \frac{{{J\left( S_{w} \right)} \cdot \sigma \cdot \cos}\;\theta}{\left( \frac{k}{\phi} \right)^{1/2}}} & (1)\end{matrix}$where J(S_(w)) is Leverett's J Function (a dimensionless unit tied towater saturation, typically having values between one and seven, withhigher values indicating lower saturation), σ is the surface tension ofa fluid in the capillary, θ is the contact angle of the fluid on thecapillary walls, and φ is the fractional porosity. High capillarypressures, as may be exhibited in the formation matrix of a lowpermeability formation, can lead to phase trapping (e.g., waterblockages, and/or phases) in the formation, for example, if reservoirpressure is insufficient to overcome the high capillary pressures.However, the problem of water blockage is less common, and in some casesmay be disregarded, in the fracture network due to the significantlyhigher permeability of the fracture network.

Because the fracture network typically acts as a conduit that transmitsresources from the formation to the wellbore, increasing the fracturenetwork's effective permeability to hydrocarbons may improve productionof hydrocarbons from the formation. The fracture network's effectivepermeability to hydrocarbons indicates the ability of the fracturenetwork to transmit or flow hydrocarbons in the presence of other fluidsin the fracture network. For example, hydrocarbons may flow more readilythrough a fracture network in the presence of a surfactant material thatmodifies the wettability of the proppant surface. In some instances, thefracture network's effective permeability to hydrocarbons should bemaximized in order to optimize or improve production. Water saturationand/or surface wettability of the proppant in the fracture network caninfluence the fracture network's effective permeability to oil, gas, andaqueous fluids. For example, the permeability of untreated 70/170 meshnatural sand to kerosene is about 1.7 Darcies (D) and the permeabilityof untreated 70/170 mesh natural sand to water is about 7.3 D; but in70/170 mesh natural sand that has been treated with a relativelystrongly adsorbing surfactant, the effective permeability of kerosene is7.6 D and the effective permeability of water is 5.7 D. The use of astrongly adsorbing surfactant may insure that the effective permeabilitymodification is not short-lived, but rather a longer term effect.

Treating the proppant with strongly adsorbing surfactant can result in acontact angle θ closer to ninety (90) degrees. According to Equation 1above, as θ approaches ninety (90) degrees, cos θ approaches zero (0),and capillary pressure approaches zero (0). In some implementations, theuse of an adsorbing surfactant modifies the proppant surface to achievea contact angle of approximately sixty (60) degrees, thus reducing thecapillary pressure. While lower surface tensions may also contribute tolowering capillary pressure, from a practical standpoint, modulating thewettability may have better potential for minimizing the capillarypressure in the fracture network in some cases.

In the formation matrix regime, reducing the capillary pressure by usinga strongly adsorbing surfactant to modify the contact angle may be moredifficult or impractical due to the large surface area of the formationmatrix. For example, in some instances, to sufficiently coat theformation matrix, high concentrations of the surfactant would berequired, thus making the treatment costly, and possibly costprohibitive. Treating the formation matrix with a strongly adsorbingsurfactant that extends only a small distance (e.g., centimeters,millimeters, etc.) into the reservoir may, in some cases, have little orno effect in stimulating production. For example, in some shale or tightgas formations, the surfactant may extend much less than an inch intothe reservoir. In some cases, capillary pressures in the formationmatrix (and thus, the formation of water blockages in the formationmatrix) can be reduced by returning the formation matrix surface to itspretreatment condition. The formation matrix surface may be returned toits pretreatment condition by extracting from the formation matrix anytreatment fluids injected during a treatment.

When the surface tension of the injected fluid remains low or does notchange appreciably upon injection into the formation matrix, theinjected fluid may be more efficiently and/or more completely extractedfrom the formation matrix. The surface tension of the injected fluid mayincrease if surfactant adsorbs onto the mineral surface of the formationmatrix. That is to say, the concentration of the surfactant in the fluidmay be depleted as a result of the surfactant adsorbing to the formationmatrix surface, and consequently, the surface tension of the fluid mayrise. For example, the surfactant molecules in a solution of stronglyadsorbing surfactants may preferentially coat the mineral surfaces,which may result in an increase in the surface tension of the fluid.Consequently, when an injected fluid contains strongly adsorbingsurfactants, the injected fluid may be completely depleted of thesurfactant due to adsorption, and capillary pressures can increase by afactor of two or three in some instances. For example, Table 1 belowshows example values of surface tension for deionized water (“DI water”)and deionized water with 0.2 percent concentration of surfactant (“DIwater+0.2% Surfactant).

TABLE 1 Surface tensions for selected fluids Fluid Surface Tension(dynes/cm) DI water 72 DI water + 0.2% surfactant 23.7Based on the values from Table 1, when DI water is substituted for Dlwater+0.2% surfactant, the surface tension value in Equation 1 increasesby a factor of approximately 2.5. Injecting surfactants that do notadsorb, and/or surfactants that adsorb minimally, onto mineral surfacesmay reduce or prevent the surface tension from changing appreciably uponinjection into the formation matrix, which may prevent an increase incapillary pressure in the formation matrix.

The example fluid testing system 200 includes a computing subsystem 202,a measuring subsystem 204, a fluid subsystem 206, test materials 207,and may include additional materials, equipment, and subsystems used toimplement fluid testing techniques. All or part of the computingsubsystems 202 and/or the measuring subsystems 204 may be integral with,separate from, and/or communicably coupled to the fluid subsystem 206.As shown in FIG. 2, the materials 207 may include solvents 208,additives 210, solid samples 212, and/or other materials.

The fluid subsystem 206 may include laboratory equipment for preparingand holding fluid samples during fluid tests. For example, the fluidsubsystem 206 may include beakers, vials, pipettes, cylinders, fluidcontainers, glassware, plastics, metals, ceramics, slides and/or otherequipment that can be used to transfer and contain fluid samples fortesting. The fluid subsystem 206 may include stirrers, mixers,agitators, heating equipment, cooling equipment, pumps, hoses, tubing,and/or other equipment that can be used to prepare and mix fluid samplesfor testing. The fluid subsystem 206 may include micro-fluidic devices,macro-fluidic devices, and/or other devices of other appropriate sizes.The fluid subsystem 206 may include a condenser, a decanter, and/or adistiller for purifying or separating fluids. In some implementations,safety equipment, protective equipment, sanitary equipment, vents,hoods, and/or other types of equipment may also be used in connectionwith the fluid subsystem 206.

The fluid subsystem 206 is used to prepare fluid samples from thematerials 207, which may include the solvents 208, the additives 210,the solid samples 212, and/or other materials. Solvents 208 may includestimulation treatment fluids and/or fracturing fluids. For example, thesolvent 208 may include water, deionized water, brine, and/or othertypes of solvents. Additives 210 may include surfactant materials and/orother materials that can be added to the solvents 208. For example, theadditives 210 may include surfactants materials that strongly or weaklyadsorb to surfaces of one or more of the solid samples 212; theadditives 210 may include other types of surfactants materials, such asthose that do not adsorb to surfaces of the solid samples 212. In someimplementations, the materials 207 include pre-mixed testing fluids thatinclude mixtures of one or more additives 210 and/or one or moresolvents 208. The additives may include cationic, anionic, nonionic,and/or zwitterionic surfactants. The additives may include other typesof surfactant materials.

Examples of cationic surfactants include, but are not limited to, alkylamines, alkyl diamines, alkyl ether amines, alkyl quaternary ammoniumcompounds, dialkyl quaternary ammonium compounds, ester quaternaryammonium compounds, erucyl bis(2-hydroxyethyl)methyl ammonium chlorides,bis(2-hydroxyethyl)erucylamine, erucyl trimethyl ammonium chlorides,N-methyl-N,N-bis(2-hydroxyethyl)rapeseed ammonium chlorides, oleylmethyl bis(hydroxyethyl)ammonium chlorides, octadecyl methylbis(hydroxyethyl)ammonium bromides, octadecyl tris(hydroxyethyl)ammoniumbromides, octadecyl dimethyl hydroxyethyl ammonium bromide, cetyldimethyl hydroxyethyl ammonium bromide, cetyl methylbis(hydroxyethyl)ammonium salicylates, cetyl methylbis(hydroxyethyl)ammonium 3,4-dichlorobenzoates, cetyltris(hydroxyethyl)ammonium iodides, cosyl dimethyl hydroxyethyl ammoniumbromides, cosyl methyl bis(hydroxyethyl)ammonium chlorides, cosyltris(hydroxyethyl)ammonium bromides, dicosyl dimethyl hydroxyethylammonium bromides, dicosyl methyl bis(hydroxyethyl)ammonium chlorides,dicosyl tris(hydroxyethyl)ammonium bromides, hexadecyl ethylbis(hydroxyethyl)ammonium chlorides, hexadecyl isopropylbis(hydroxyethyl)ammonium iodide cetylaminos, N-octadecyl pyridiniumchlorides, N-soya-N-ethyl morpholinium ethosulfates, methyl-1-oleylamido ethyl-2-oleyl imidazolinium-methyl sulfates, methyl-1-tallow amidoethyl-2-tallow imidazolinium-methyl sulfates, trimethylcocoammoniumchlorides, trimethyltallowammonium chlorides, dimethyldicocoammoniumchlorides, bis(2-hydroxyethyl)tallow amines,bis(2-hydroxyethyl)coco-amines, cetylpyridinium chlorides, and anyderivatives and combinations thereof. The term “derivative” includes anycompound that is made from one of the listed compounds, for example, byreplacing one atom in the listed compound with another atom or group ofatoms, rearranging two or more atoms in the listed compound, ionizingone of the listed compounds, or creating a salt of one of the listedcompounds.

Examples of anionic sufactants include, but are not limited to, sodiumdecylsulfates, sodium lauryl sulfates, alpha olefin sulfonates,alkylether sulfates, alkyl phosphonates, alkane sulfonates, fatty acidsalts, arylsulfonic acid salts, lignosulfonates, alkylbenzenesulfonates, petroleum sulfonates, naphthalene sulfonates, olefinsulfonates, alkyl sulfates, sulfated natural fats and oils, sulfatedfatty acids, particularly sulfated oleic acid, sulfated alkanolamides,sulfated esters, sulfated alkyl phenols, sulfated alcohols, 2-sulfoethyesters of fatty acids, monalkylsulfosuccinates, dialkyl sulfosuccinates,polyethoxy carboxylic acids, acylated protein hydrolysates,N-acylsarcosinates, alkyl carboxylic acids, cycloalkyl carboxylic acids,aryl carboxylic acids, alkyl phosphates, alkyl thiophosphates, alkylpolyphosphates, ethoxylated phosphate esters, and any derivitatives andcombinations thereof.

Examples of zwitterionic surfactants include alkyl betaines, alkyl amidobetaines, alkyl imidazolines, alkyl amine oxides, alkyl quaternaryammonium carboxylates, and any derivatives and combinations thereof.

Solid samples 212 may include rocks, minerals, sand, proppants,materials extracted from a subterranean formation or an outcropping,and/or other types of solid materials. The solid samples 212 may includegranular rock material, granular mineral material, graded sand, proppantmaterials, crushed material from a subterranean formation, cuttings froma subterranean formation, and/or other types of solid materials. Forexample, the solid samples 212 may include sand, granite, sandstone,shale, limestone, and/or other proppant materials. The fluid testingsystem 200 may include a crusher for crushing solid samples, a mortar, apestle, a screen, a sifter, and/or other types of equipment forpreparing granulated samples. In some implementations, a solid sample212 may include solid grains in a specified range of sizes, and/or solidgrains corresponding to a specified size distribution.

The measuring subsystem 204 may include one or more measuring devicesthat measures properties of the materials 207 before and/or after thematerials 207 are combined in the fluid subsystem 206. The measuringsubsystem 204 may include digital, analog, electronic, pneumatic,mechanical, chemical, and/or other types of measuring devices. Themeasuring subsystem 204 may include micro-fluidic measuring devices,macro-fluidic measuring devices, and/or measuring devices of anyappropriate size. The measuring subsystem 204 may include devices formeasuring temperature, volume, pressure, surface tension, surfaceenergy, mass, weight, contact angle, length, force, pH, flow rate,electrical properties and/or other properties. The measuring subsystem204 may include, for example, scales, balances, thermometers,thermocouples, tensiometers, goniometers, graduated cylinders, measuringcups, transducers, timing instruments, force gauges, pressure gauges,and/or other devices. The measuring subsystem 204 may include manuallyoperated and/or automated measuring devices.

In some implementations, the measuring subsystem 204 includes a testsurface and a contact angle goniometer that measures a contact anglebetween a liquid and the test surface. The test surface may include aflat surface, such as, for example, a test slide or another type ofsurface. The test surface may include a glass, ceramic, plastic,mineral, and/or other materials. The test surface may include a curvedsurface, such as, for example, a tube, a pipette, or another type ofcurved surface. In some implementations, the measuring subsystem 204includes a tensiometer that measures a surface tension of a liquidsample.

The computing subsystem 202 may receive input data and generate outputdata. The computing subsystem 202 may include any of various types ofdevices, including, but not limited to, a personal computer system,desktop computer, laptop, notebook, mainframe computer system, handheldcomputer, workstation, graphing calculator, network computer,application server, storage device, a measuring device, and/or any typeof computing or electronic device. The computing subsystem 202 mayinclude measurement software, data plotting software, data analysissoftware, and/or other types of software. For example, the computingsubsystem may include National Instruments LabVIEW software, theMathWorks MATLAB software, Microsoft Excel spreadsheet software, and/orother data analysis software.

The example computing subsystem 202 includes a processor 240, a memory220, and input/output controllers 230 communicably coupled by a bus 260.The memory 220 can include, for example, a random access memory (RAM), astorage device (e.g., a writable read-only memory (ROM) and/or others),a hard disk, and/or another type of storage medium. The memory 220 canstore instructions (e.g., computer code) associated with an operatingsystem, computer applications, and/or other resources. The memory 220can also store application data and data objects that can be interpretedby one or more applications and/or virtual machines running on thecomputing subsystem 202. The computing subsystem 202 can bepreprogrammed and/or it can be programmed (and reprogrammed) by loadinga program from another source (e.g., from a CD-ROM, from anothercomputer device through a data network, and/or in another manner). Thedata stored in the memory 220 may include information received from themeasuring subsystem 204 and/or from the testing subsystem 206, which mayinclude raw data and/or signals, measured values, test result values,and/or other types of data. For example, the data stored in the memory220 may include measurements of surface tension, contact angle, volume,temperature, fluid concentration, time, and/or other types ofmeasurements.

The input/output controllers 230 may be coupled to input/output devices(e.g., a monitor 270, a printer, a mouse, a keyboard, and/or otherinput/output devices), the measurement subsystem 204, the fluidsubsystem 206, a data communication network 280, and/or other systemsand subsystems. The input/output devices receive and transmit data inanalog or digital form over communication links such as a serial link,wireless link (e.g., infrared, radio frequency, and/or others), parallellink, and/or another type of link. The network 280 can include any typeof data communication network. For example, the network 280 can includea wireless and/or a wired network, a Local Area Network (LAN), a WideArea Network (WAN), a private network, a public network (such as theInternet), a WiFi network, a network that includes a satellite link,and/or another type of data communication network.

In one aspect of operation, multiple test fluids are prepared using thefluid subsystem 206. For example, each test fluid may be prepared in aseparate container. Each test fluid may include a differentconcentration of a solvent material 208 and an additive material 210.For example, each test fluid may be prepared by mixing a specific amountof additive 210 and solvent 208 in a test container. An initial value ofa property of each test fluid is measured using the measuring subsystem204. For example, an initial surface tension or and/or contact angle maybe measured for each test fluid. Data values for the initialmeasurements are stored in the memory 220. A sample of solid material212 is added to each test fluid in the fluid subsystem 206. After thesolid material is added, one or more subsequent values of the propertyare measured for each test fluid using the measuring subsystem 204. Forexample, one or more subsequent surface tension measurements and/orcontact angle measurements may be taken for each test fluid. Data valuesfor the subsequent measurements are stored in the memory 220. Theprocessor 240 may execute instructions to analyze the measurement datastored in the memory 220. For example, the processor 240 may determine achange in the measured property, a change in time, and/or other values.The measured data and/or the results of data analysis may be displayedon the monitor 270, stored in the memory 220, communicated over thenetwork 280, and/or further processed.

In some implementations, a surfactant selected for proppant-laden stagesof treatment has a contact angle greater than or equal to forty degrees(i.e., θ≧40°), which may increase the effective permeability ofhydrocarbons in the fracture network. In some implementations, thesurfactant for proppant-laden stages has multiple cationic sites toinsure a relatively permanent bond to the proppant surface. In someimplementations, a weakly-adsorbing or non-adsorbing surfactant may alsobe included in the proppant-laden stages to compensate for the leak-offof this fluid into the formation.

FIGS. 3 and 4 show data from an example fluid test. The example fluidtest shown in FIGS. 3 and 4 can be used to identify a treatment fluidthat will retain low surface tension in a formation matrix of asubterranean formation. In the examples shown, the additive is gas perm1000, the solvent is water, and the solid material is 100 mesh sand.Other types of fluids and/or solid materials may be used. To begin theexample fluid test, the surface tensions of fluids with differentconcentrations of an additive are measured. For example, FIG. 3 is aplot 300 of surface tension versus additive concentration. Percentconcentrations of the additive are represented in log scale on thehorizontal axis of the plot 300, and surface tensions in units ofmillinewtons per meter (mN/m) are represented in linear scale on thevertical axis of the plot 300. The square data points 310 a, 310 b, 310c, 310 d, 310 e, and 310 f (collectively 310) represent measured surfacetension values. Based on the measured values 310, surface tension as afunction of additive concentration can be determined. The dotted line312 represents a best-fit function of surface tension versus additiveconcentration.

Continuing the example fluid test, the data points 310 and/or thebest-fit function can be used to identify three concentrations ofsolution to be tested. The three concentrations chosen for testing inthe example shown are identified as “Conc. 1,” “Conc. 2,” and “Conc. 3”on the plot 300. The first concentration (“Conc. 1”) is the lowestconcentration at which a measurable decrease in surface tension isobserved in the data. The third concentration (“Conc. 3”) is thecritical micelle concentration. The critical micelle concentration(“CMC”) is the concentration at which micelles spontaneously form in thetest fluid. The CMC may be determined based on visual inspection, bymeasurement, by an automated data analysis, and/or by another technique.The second concentration (“Conc. 2”) is a concentration intermediate thefirst and third concentrations. The three concentrations may be chosenso as to maximize the sensitivity of subsequent measurements. Adifferent number of test concentrations may be selected based on thesame and/or different criteria.

Continuing the example fluid test, three test fluids are prepared; eachprepared test fluid has one of the three chosen concentrations. That isto say, one of the test fluids is a mixture of the additive at the firstconcentration (“Conc. 1”); one of the test fluids is a mixture of theadditive at the second concentration (“Conc. 2”); one of the test fluidsis a mixture of the additive at the third concentration (“Conc. 3”). Thesurface tension of the three test fluids is measured and used as abaseline or control measurement. For example, FIG. 4 shows a plot 400 ofsurface tension versus additive concentration. Concentrations of theadditive in units of gallon per thousand gallons (gal/Mgal) arerepresented in log scale on the horizontal axis of the plot 400, andsurface tensions in units of mN/m are represented in linear scale on thevertical axis of the plot 400. The square data points 408 a, 408 b, and408 c represent the baseline measurements.

Continuing the example fluid test, crushed formation material (e.g.,granite, shale, sandstone, coal, and/or others) and/or proppant material(e.g., graded sand, and/or others) are added to each of the three testfluids. The surface tension for each test fluid is recorded as afunction of time until no measurable change is recorded. In the examplefluid test, the surface tension of each test fluid reached a steadyvalue before sixty (60) minutes from the time that the solid sample wasadded. The circle data points 410 a, 410 b, and 410 c represent thesurface tension measurements after sixty (60) minutes. The differencebetween the baseline surface tension measurement and the subsequentsurface tension measurement for each test fluid represents the testfluid's response to adding the sample of solid material. For example,the difference between the data points 408 a and 410 a represents aresult of adding the sample of solid material to the first test fluid;the difference between the data points 408 b and 410 b represents aresult of adding the sample of solid material to the second test fluid;and the difference between the data points 408 c and 410 c represents aresult of adding the sample of solid material to the third test fluid.

The response of each test fluid can be used to determine the additive'ssuitability for a stimulation treatment. For example, the additive maybe selected for a stimulation treatment based on whether and/or how muchthe surface tension changes in response to adding the sample of solidmaterial. An additive may be selected for a stimulation treatment basedon the surface tension changing less than a threshold amount in responseto adding the sample of solid material. An additive may be selected fora stimulation treatment based on the surface tension demonstrating nomeasurable change in response to adding the sample of solid material. Nomeasurable change in surface tension may indicate that there was noappreciable adsorption of the additive to the added solid material andthat the additive remained in solution serving to maintain the desiredsurface tension.

Other fluid tests may be conducted to determine suitability of anadditive for a stimulation treatment. One example alternative fluid testmay be used to identify an additive that will strongly adsorb to aproppant material and reduce a fluid contact angle in a fracture systemof a subterranean formation. For example, in some implementations, inaddition to measuring the initial surface tension for each of the threetest fluids, an initial contact angle is measured for each of the threetest fluids, and the initial contact angles serve as the baselinemeasurement. A contact angle for a test fluid may be measured, forexample, by immersing a test slide in the test fluid for a period oftime and measuring the resulting contact angle between the test surfaceand the surface of the test fluid. After solid material has been addedand the surface tension has reached a steady value (e.g., after sixty(60) seconds, or another time period), the liquid test fluid is decantedfrom the mixture and the contact angle of the liquid is measured again.An additive may be selected for a stimulation treatment based ondifferences between the baseline contact angle measurement and thesubsequent contact angle measurement. For example, an additive may beselected for a stimulation treatment based on the contact angledemonstrating a measurable reduction in response to adding the sample ofsolid material; an additive may be selected based on the contact anglebeing reduced by at least a threshold amount. A reduction in contactangle may indicate that the additive adsorbed to surface of the solidmaterial.

FIG. 5 is a flow chart of an example process 500 for applying astimulation treatment to a subterranean formation. All or some of theoperations of the example process 500 may be implemented using theexample well system 100 of FIG. 1 and/or another system. In someimplementations, the process 500 includes fewer, additional, and/ordifferent operations performed in the same or a different order.

At 504, multiple test fluids are prepared; each test fluid includes anadditive. The additive may include, for example, a surfactant materialto be tested. In some implementations, each test fluid is prepared in aseparate beaker or other type of fluid container. In someimplementations, each test fluid includes a different concentration ofthe additive in a solvent fluid. Initial measurements of each test fluidare made before adding solid material to each test fluid.

At 506, a sample of solid material is added to each of the test fluids.The sample of solid material may include granular rock material,granular mineral material, graded sand, a proppant material, cuttingsfrom a subterranean formation, crushed material from a subterraneanformation, and/or another solid material. The mineral composition of thesample of solid material may be selected based on a mineral compositionof a subterranean formation, a mineral composition of a proppantmaterial, and/or other factors.

At 508, a result of adding the sample of solid material is determinedfor each test fluid. The result may be determined using a measuringdevice, such as, for example, a tensiometer, a test slide, and/oranother device. For example, determining a result of adding the sampleof solid material may include determining a difference between aninitial surface tension and a final surface tension, determining adifference between an initial surface energy and a final surface energy,determining a difference in an initial contact angle and a final contactangle, determining a difference in an initial surface wettability and afinal surface wettability, and/or determining another difference.Moreover, determining a result of adding the sample of solid materialmay include determining a change or no measurable change in surfacetension, determining a change or no measurable change in surface energy,determining a change or no measurable change in contact angle,determining a change or no measurable change in surface wettability,and/or making another determination. The result of adding the solidmaterial to a test fluid may be determined by a computing subsystem. Forexample, measured values may be received by the computing system, andthe computing system may include logic that identifies the result basedon the received values.

Based on the response, it may be determined that the additive is notsuitable for a stimulation treatment. For example, a response thatincludes a change in surface tension may indicate that the additive isan adsorbing surfactant that is not suitable for a treatment where anon-adsorbing surfactant is desired. As another example, a response thatincludes no measurable change, or only a small change, in contact anglemay indicate that the additive is a non-adsorbing or weakly-adsorbingsurfactant that is not suitable for a treatment where astrongly-adsorbing surfactant is desired. When it is determined that theadditive is not suitable for a stimulation treatment, the process 500may terminate, or may continue at 504 with testing a new additive.

Based on the response, it may be determined that the additive issuitable for a stimulation treatment. For example, a response thatincludes no measurable change, or only a small change, in surfacetension may indicate that the additive is a non-adsorbing surfactantthat is suitable for treating the formation matrix during a pad phase ofa stimulation treatment. As another example, a response that includes adecrease in contact angle may indicate that the additive is an adsorbingsurfactant that is suitable for treating a fracture system during aproppant phase of a stimulation treatment. When it is determined thatthe additive is suitable for a stimulation treatment, the process 500may continue at 510.

At 510, an additive is selected for a stimulation treatment based on theresults. An additive may be selected for a stimulation treatment basedon the suitability of the additive for a given phase of a stimulationtreatment in a given subterranean formation and/or with a given proppantmaterial. For example, if the solid material added to the test fluid (at506) includes material extracted from a particular subterraneanformation, the test results may indicate how the measured properties ofthe test fluid will be behave in the particular subterranean formationor a similar formation. As another example, if the solid material addedto the test fluid (at 506) includes a particular proppant, the testresults may indicate how the measured properties of the test fluid willbe behave in a subterranean formation that includes the particularproppant.

At 512, a treatment fluid containing the additive is injected into asubterranean formation. The treatment fluid may be applied to thesubterranean formation by a fracture treatment subsystem or another typeof stimulation treatment subsystem. The stimulation treatment subsystemmay include a tubular conduit installed in a well bore defined in thesubterranean formation. The treatment fluid may be communicated by apump into the tubular conduit. The treatment fluid may be communicatedthrough the tubular conduit and into the formation through an outlet,such as, for example, a perforation in the tubular conduit or anothertype of outlet.

FIG. 6 is a flow chart of an example fluid testing process 600. All orsome of the operations of the example process 600 may be implementedusing the example fluid testing system 200 of FIG. 2 and/or anothersystem. In some implementations, the process 600 includes fewer,additional, and/or different operations performed in the same or adifferent order.

At 602, an initial surface tension of a test fluid is measured. The testfluid includes a surfactant. At 604, a sample of solid material is addedto the test fluid. The solid material may include crushed materialand/or cuttings from a subterranean formation, proppant material, and/orother types of solids. The resulting mixture may be stirred, mixed, oragitated. At 606, a final surface tension of the test fluid is measured.The final surface tension may be measured one or more times, after apredetermined amount of time, after the surface tension has reached asteady state, and/or after a different amount of time. At 608, adifference between the initial surface tension and a final surfacetension is determined. The difference may be used to determine whetherthe surfactant is suitable for a stimulation treatment. Based on themeasured difference, the surfactant may be used, for example, in a padphase, a proppant phase, and/or a flush phase of a stimulationtreatment. For example, if the difference is zero or immeasurably small,the surfactant may be used to treat a formation matrix during a padphase. As another example, if the difference is zero or immeasurablysmall, the surfactant may be used to treat a formation matrix during aproppant-laden phase of treatment.

FIG. 7 is a flow chart of another example fluid testing process 700. Allor some of the operations of the example process 700 may be implementedusing the example fluid testing system 200 of FIG. 2 and/or anothersystem. In some implementations, the process 600 includes fewer,additional, and/or different operations performed in the same or adifferent order.

At 702, an initial contact angle between a test fluid and a test surfaceis measured. The test fluid includes a surfactant material. An initialsurface tension may also be measured. At 704, a sample of solid materialis added to the test fluid. The solid material may include crushedmaterial and/or cuttings from a subterranean formation, proppantmaterial, and/or other types of solids. The resulting mixture may bestirred, mixed, or agitated. The surface tension of the mixture may bemonitored.

At 706, a final contact angle between the test fluid and the testsurface is measured. The final contact angle may be measured one or moretimes, after a predetermined amount of time, after the surface tensionhas reached a steady state, and/or after a different amount of time. Thefinal contact angle may be measured after the liquid of the test fluidis filtered, decanted, or otherwise separated from the solid material.The final contact angle may be measured using the same or a differenttest surface as the initial contact angle.

At 708, a difference between the initial contact angle and the finalcontact angle is determined. The difference may be used to determinewhether the surfactant is suitable for a stimulation treatment. Based onthe measured difference, the surfactant may be used, for example, in apad phase, a proppant phase, and/or a flush phase of a stimulationtreatment. For example, if the difference indicates a reduction of thecontact angle as a result of adding the solid material, the surfactantmay be used to treat a fracture system during a proppant phase.

Some embodiments of subject matter and operations described in thisspecification can be implemented in digital electronic circuitry, or incomputer software, firmware, or hardware, including the structuresdisclosed in this specification and their structural equivalents, or incombinations of one or more of them. Some embodiments of subject matterdescribed in this specification can be implemented as one or morecomputer programs, i.e., one or more modules of computer programinstructions, encoded on computer storage medium for execution by, or tocontrol the operation of, data processing apparatus. A computer storagemedium can be, or can be included in, a computer-readable storagedevice, a computer-readable storage substrate, a random or serial accessmemory array or device, or a combination of one or more of them.Moreover, while a computer storage medium is not a propagated signal, acomputer storage medium can be a source or destination of computerprogram instructions encoded in an artificially generated propagatedsignal. The computer storage medium can also be, or be included in, oneor more separate physical components or media (e.g., multiple CDs,disks, or other storage devices).

Some of the operations described in this specification can beimplemented as operations performed by a data processing apparatus ondata stored on one or more computer-readable storage devices or receivedfrom other sources. The term “data processing apparatus” encompasses allkinds of apparatus, devices, and machines for processing data, includingby way of example a programmable processor, a computer, a system on achip, or multiple ones, or combinations, of the foregoing. The apparatuscan include special purpose logic circuitry, e.g., an FPGA (fieldprogrammable gate array) or an ASIC (application specific integratedcircuit). The apparatus can also include, in addition to hardware, codethat creates an execution environment for the computer program inquestion, e.g., code that constitutes processor firmware, a protocolstack, a database management system, an operating system, across-platform runtime environment, a virtual machine, or a combinationof one or more of them.

A computer program (also known as a program, software, softwareapplication, script, or code) can be written in any form of programminglanguage, including compiled or interpreted languages, declarative orprocedural languages. A computer program may, but need not, correspondto a file in a file system. A program can be stored in a portion of afile that holds other programs or data (e.g., one or more scripts storedin a markup language document), in a single file dedicated to theprogram in question, or in multiple coordinated files (e.g., files thatstore one or more modules, sub programs, or portions of code). Acomputer program can be deployed to be executed on one computer or onmultiple computers that are located at one site or distributed acrossmultiple sites and interconnected by a communication network.

Some of the processes and logic flows described in this specificationcan be performed by one or more programmable processors executing one ormore computer programs to perform actions by operating on input data andgenerating output. The processes and logic flows can also be performedby, and apparatus can also be implemented as, special purpose logiccircuitry, e.g., an FPGA (field programmable gate array) or an ASIC(application specific integrated circuit).

Processors suitable for the execution of a computer program include, byway of example, both general and special purpose microprocessors, andany one or more processors of any kind of digital computer. Generally, aprocessor will receive instructions and data from a read only memory ora random access memory or both. The essential elements of a computer area processor for performing actions in accordance with instructions andone or more memory devices for storing instructions and data. A computermay also include, or be operatively coupled to receive data from ortransfer data to, or both, one or more mass storage devices for storingdata, e.g., magnetic, magneto optical disks, or optical disks. However,a computer need not have such devices. Devices suitable for storingcomputer program instructions and data include all forms of non volatilememory, media and memory devices, including by way of examplesemiconductor memory devices (e.g., EPROM, EEPROM, flash memory devices,and others), magnetic disks (e.g., internal hard disks, removable disks,and others), magneto optical disks, and CD ROM and DVD-ROM disks. Theprocessor and the memory can be supplemented by, or incorporated in,special purpose logic circuitry.

To provide for interaction with a user, embodiments of the subjectmatter described in this specification can be implemented on a computerhaving a display device (e.g., a CRT (cathode ray tube) or LCD (liquidcrystal display) monitor, or another type of display device) fordisplaying information to the user and a keyboard and a pointing device(e.g., a mouse, a trackball, a tablet, a touch sensitive screen, oranother type of pointing device) by which the user can provide input tothe computer. Other kinds of devices can be used to provide forinteraction with a user as well; for example, feedback provided to theuser can be any form of sensory feedback, e.g., visual feedback,auditory feedback, or tactile feedback; and input from the user can bereceived in any form, including acoustic, speech, or tactile input. Inaddition, a computer can interact with a user by sending documents toand receiving documents from a device that is used by the user; forexample, by sending web pages to a web browser on a user's client devicein response to requests received from the web browser.

A client and server are generally remote from each other and typicallyinteract through a communication network. Examples of communicationnetworks include a local area network (“LAN”) and a wide area network(“WAN”), an inter-network (e.g., the Internet), a network comprising asatellite link, and peer-to-peer networks (e.g., ad hoc peer-to-peernetworks). The relationship of client and server arises by virtue ofcomputer programs running on the respective computers and having aclient-server relationship to each other.

While this specification contains many specific implementation details,these should not be construed as limitations on the scope of anyinventions or of what may be claimed, but rather as descriptions offeatures specific to particular embodiments. Certain features that aredescribed in this specification in the context of separate embodimentscan also be implemented in combination in a single embodiment.Conversely, various features that are described in the context of asingle embodiment can also be implemented in multiple embodimentsseparately or in any suitable subcombination. Moreover, althoughfeatures may be described above as acting in certain combinations andeven initially claimed as such, one or more features from a claimedcombination can in some cases be excised from the combination, and theclaimed combination may be directed to a subcombination or variation ofa subcombination.

Similarly, while operations are depicted in the drawings in a particularorder, this should not be understood as requiring that such operationsbe performed in the particular order shown or in sequential order, orthat all illustrated operations be performed, to achieve desirableresults. In certain circumstances, multitasking and parallel processingmay be advantageous. Moreover, the separation of various systemcomponents in the embodiments described above should not be understoodas requiring such separation in all embodiments, and it should beunderstood that the described program components and systems cangenerally be integrated together in a single software product orpackaged into multiple software products.

In the present disclosure, “each” refers to each of multiple items oroperations in a group, and may include a subset of the items oroperations in the group and/or all of the items or operations in thegroup. In the present disclosure, the term “based on” indicates that anitem or operation is based at least in part on one or more other itemsor operations—and may be based exclusively, partially, primarily,secondarily, directly, or indirectly on the one or more other items oroperations.

A number of embodiments of the invention have been described.Nevertheless, it will be understood that various modifications may bemade without departing from the spirit and scope of the invention.Accordingly, other embodiments are within the scope of the followingclaims.

What is claimed is:
 1. A method comprising: using a measuring device todetermine a result of adding a sample of a solid material to a testfluid, the test fluid comprising an additive; and determining asuitability of the additive for use in a stimulation treatment of asubterranean formation based on an adsorption characteristic of theadditive determined from the result.
 2. The method of claim 1, whereinusing the measuring device to determine the result comprises: using themeasuring device to measure a first surface tension of the test fluidbefore adding the sample to the test fluid; and using the measuringdevice to measure a second surface tension of the test fluid afteradding the sample to the test fluid, wherein the result comprises adifference between the first surface tension and the second surfacetension.
 3. The method of claim 1, wherein using the measuring device todetermine the result comprises: using the measuring device to measure afirst contact angle between the test fluid and a test surface beforeadding the sample to the test fluid; and using the measuring device tomeasure a second contact angle between the test fluid and the testsurface after adding the sample to the test fluid, wherein the resultcomprises a difference between the first contact angle and the secondcontact angle.
 4. The method of claim 3, wherein measuring the secondcontact angle comprises measuring the second contact angle after asurface tension of the test fluid has reached a steady value.
 5. Themethod of claim 3, wherein the second contact angle is greater than thefirst contact angle, and determining the suitability comprisesdetermining that the additive is suitable for a proppant phase of thestimulation treatment.
 6. The method of claim 1, wherein the test fluidcomprises a first test fluid, the first test fluid comprises a firstconcentration of the additive in a solvent, the sample comprises a firstsample, the result comprises a first result, and the method furthercomprises: using the measuring device to determine a second result ofadding a second sample of the solid material to a second test fluid, thesecond test fluid comprising a second concentration of the additive andthe solvent; and using the measuring device to determine a third resultof adding a third sample of the solid material to a third test fluid,the third test fluid comprising a third concentration of the additiveand the solvent; wherein the suitability is determined based on thefirst result, the second result, and the third result.
 7. The method ofclaim 6, wherein the third concentration comprises a critical micelleconcentration.
 8. The method of claim 1, wherein the sample comprises atleast one of granular rock material, granular mineral material, gradedsand, a proppant material, cuttings from the subterranean formation, orcrushed material from the subterranean formation.
 9. The method of claim1, wherein determining a suitability of the additive comprises using adata processor to analyze the result.
 10. The method of claim 1, whereindetermining a suitability of the additive comprises determining from theresult that the additive is a non-adsorbing surfactant.
 11. The methodof claim 1, wherein determining a suitability of the additive comprisesdetermining from the result that the additive is a weakly-adsorbingsurfactant.
 12. The method of claim 1, wherein determining a suitabilityof the additive comprises determining from the result that the additiveis a strongly-adsorbing surfactant.
 13. A method for performing afracture treatment, the method comprising: receiving information on anadditive selected for treating a subterranean formation, the additiveselected based on an adsorption characteristic determined from ameasured result of adding a sample of a solid material to a test fluidcomprising the additive; and injecting the additive into thesubterranean formation through a well bore defined in the subterraneanformation.
 14. The method of claim 13, wherein the sample comprises atleast one of cuttings from the subterranean formation or crushedmaterial from the subterranean formation.
 15. The method of claim 13,wherein the subterranean formation comprises a first subterraneanformation, and the sample comprises at least one of cuttings from asecond subterranean formation or crushed material from a secondsubterranean formation.
 16. The method of claim 13, wherein the samplecomprises a volume of a proppant material, and injecting the additivecomprises injecting the additive and the proppant material into thesubterranean formation.
 17. The method of claim 13, wherein the samplecomprises a volume of a proppant material, and injecting the additivecomprises injecting the additive into a region of the subterraneanformation comprising the proppant material.
 18. The method of claim 13,the additive selected based on at least one of: the measured result ofadding the sample to the test fluid comprising no change in a surfacetension of the test fluid; or the measured result of adding the sampleto the test fluid comprising an increase in a contact angle of the testfluid and a test surface.
 19. A system comprising: a fluid testingsubsystem that determines a suitability of an additive for a stimulationtreatment based on an adsorption characteristic of the additivedetermined from a result of adding a sample of a solid material to atest fluid comprising the additive; and a stimulation treatmentsubsystem that applies the additive to a subterranean formation througha well bore defined in the subterranean formation.
 20. The system ofclaim 19, wherein the subterranean formation comprises shale and thewell bore comprises a horizontal well bore.
 21. The system of claim 19,wherein the subterranean formation comprises a formation matrix and afracture network.
 22. The system of claim 19, wherein the fluid testingsubsystem comprises: a fluid container that receives: a test fluidcomprising the additive; and the sample of solid material; and atensiometer that measures a surface tension of the test fluid.
 23. Thesystem of claim 19, wherein the fluid testing subsystem comprises: afluid container that receives: a test fluid comprising the additive; andthe sample of solid material; and a contact angle goniometer thatmeasures a contact angle between the test fluid and a test surface. 24.The system of claim 19, wherein the stimulation treatment subsystemcomprises: a tubular conduit installed in the well bore; a pump thatcommunicates a treatment fluid comprising the additive into the tubularconduit; and an outlet in the well bore that receives the treatmentfluid from the tubular conduit and communicates the treatment fluid intothe subterranean formation.